EP0389150B1 - Elimination de sulfures - Google Patents

Elimination de sulfures Download PDF

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Publication number
EP0389150B1
EP0389150B1 EP90302513A EP90302513A EP0389150B1 EP 0389150 B1 EP0389150 B1 EP 0389150B1 EP 90302513 A EP90302513 A EP 90302513A EP 90302513 A EP90302513 A EP 90302513A EP 0389150 B1 EP0389150 B1 EP 0389150B1
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EP
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Prior art keywords
chlorite
composition according
composition
sulphide
amphoteric compound
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Expired - Lifetime
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EP90302513A
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German (de)
English (en)
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EP0389150A1 (fr
Inventor
Mark Roy Howson
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Baker Hughes Holdings LLC
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Baker Hughes Inc
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Classifications

    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
    • C10G27/02—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation with halogen or compounds generating halogen; Hypochlorous acid or salts thereof
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10S507/00—Earth boring, well treating, and oil field chemistry
    • Y10S507/927—Well cleaning fluid

Definitions

  • the present invention relates to a process for the removal of sulphides, especially hydrogen sulphide present in a crude oil or hydrocarbon feed contaminated therewith during production or processing of said feed or in water separated from said feed.
  • Sulphides in general and hydrogen sulphide in particular is an undesirable by-product of crude oil production. These sulphides are toxic, have an obnoxious odour and, in the case of wet hydrogen sulphide, is highly corrosive to carbon steel.
  • R.N. Tuttle et al describe the corrosive aspects of hydrogen sulphide in relation to high strength steels in "H2S corrosion in Oil and Gas Production", National Association of Corrosion Engineers, 1981.
  • chlorite including chlorine dioxide
  • chlorite and its salts or chlorine dioxide on their own causes the corrosivity of the produced fluids to increase markedly especially when used at an injection rate over and above that required to react with all the hydrogen in such systems to mitigate this undesirable effect.
  • This must be added separately since most of the commonly-used corrosion inhibitors are either incompatible with chlorite due to its very strong oxidising potential or form insoluble precipitates or cannot be used offshore for environmental reasons e.g. Cr salts.
  • the present invention is a composition suitable for use as a sulphide scavenger, said composition comprising an aqueous solution of a chlorite and a corrosion inhibitor, characterised in that the corrosion inhibitor is an amphoteric compound of the formula wherein each of R1, R2 and R3 is the same or different group selected from H, C1-C24 alkyl, aryl, halogen, hydroxy, alkoxy, carbonylic and a heterocyclic group formed by a combination of at least two of R1, R2 and R3 and the nitrogen atom, said heterocyclic group optionally containing additional heteroatoms, R4 is a carboxylic or a sulphonic acid group, and n has a value from 1-9.
  • the corrosion inhibitor is an amphoteric compound of the formula wherein each of R1, R2 and R3 is the same or different group selected from H, C1-C24 alkyl, aryl, halogen, hydroxy, alkoxy, carbonylic and a heterocyclic group formed
  • the sulphide contaminant to be scavenged may be present in liquid or gaseous streams or in storage tanks forming part of a chemicals processing plant, e.g. crude oil processing.
  • the contaminant may be present, for instance, in (i) a crude oil feed which is either in an untreated virgin state as recovered from an oil well, or (ii) a feed that has undergone one or more preliminary treatment stages, whether physical or chemical, prior to any cracking step to which the crude oil is subjected, or (iii) an aqueous feed derived as a by-product of chemical manufacturing including crude oil recovery, whether or not associated with crude oil recovered from an oil well.
  • the feed may be crude oil derived or recovered directly from the well or that at any stage immediately prior to the gas/oil separation step, whether or not associated with water.
  • the type of chlorite used may be any chlorite which is soluble in water.
  • the chlorites are suitably alkali metal chlorites, preferably sodium chlorite.
  • the amount of the chlorite present in the composition will depend upon the extent to which the sulphide contaminant is to be removed. The precise amount used would depend upon the nature of the sulphide to be removed and the type of feed. Thus for full removal of the sulphide contaminant in a feed, the chlorite is preferably used in an amount of at least 0.5 moles per mole of the sulphide contaminant to be removed.
  • R1 and R3 are suitably C1-C4 alkyl groups, preferably CH3;
  • R2 is suitably a C10-C15 alkyl group, preferably C12-C14 alkyl group;
  • R4 is suitably a -C00- group; and
  • n is suitably 1-4, preferably 1-2.
  • the ring so formed is suitably an imidazoline ring.
  • amphoteric compound used is most preferably an alkyl betaine, especially lauryl betaine.
  • the relative proportions of the chlorite and the ampholeric compound in the composition is suitably in the range of 1:0.1 to 1:0.9 w/w respectively, preferably 1:0.4 to 1:0.7 w/w.
  • compositions of the present invention are preferably used as aqueous solutions.
  • such solutions may optionally contain a water-miscible secondary solvent, e.g. an alcohol or a glycol to enhance the freeze-thaw properties of the composition.
  • a water-miscible secondary solvent e.g. an alcohol or a glycol to enhance the freeze-thaw properties of the composition.
  • the treatment of the contaminated feed with the compositions of the present invention can be effected at temperatures ranging from below ambient to about 150°C.
  • the scavenger formulations of the present invention are particularly effective in treating wet crude oil, i.e. crudes containing 5 - 95% w/w water and containing hydrogen sulphide at levels of 1 - 1000 ppm at a temperature e.g. in the range from 15-60°C and a pH e.g. in the range of 4.0-6.9. These formulations are substantially free of any corrosive effects under these conditions.
  • a feature of the present inventions is that the use of these scavenger formulations have significant advantages over those used hitherto: For instance these compositions are:
  • Corrosion rate measurements were performed using LPR (linear polarisation resistance) method.
  • a rig was constructed from polytetrafluroethylene (PTFE), nylon and silicone rubber.
  • the rig contained two separate corrosion cells, connected in series but some distance apart. Each cell contained three concentric, mild steel electrodes, 8.6cm2 surface area, with PTFE spacers.
  • a multichannel peristaltic pump controlled the addition of all the chemicals through the rig. Concentrations of the various reactants were adjusted to give the desired final concentration of sulphide and scavenger composition in the flowing stream. A flow rate of 45 to 50cm3/min (total fluids) was set. Deareated saline water (4.3% NaCl) buffered to a pH of 4.8 with NaHCO3 and CO2 was treated with 35 to 40ppm w/w (in fluid) of H2S. Corrosion rate measurements were continuously monitored at the point of injection, cell A, and further downstream, cell B. In this way the most corrosive environment (highest excess of oxidising agent) and the least corrosive environment (dynamic equilibrium of reactants) were obtained. Sample points of the untreated and the treated H2S stream enabled assessment of the efficiency of the H2S scavenging reaction (Iodimetric analysis, see Vogel's Textbook of Quantitative Inorganic Analysis, 4th Edition, Longmans).
  • Table 1 The effect of the injection of a solution that contains only sodium chlorite is shown in Table 1.
  • the corrosion rate does not increase above that of the background until the level of the scavenger equals that required to react with all the hydrogen sulphide at this concentration the corrosion rate in the injection cell increases significantly although the downstream corrosiveness is still that of the background. Above this concentration the corrosion rate increases to unacceptable levels.
  • Table 2 shows that by incorporating a betaine into the formulation the corrosion rate is controlled to less than 30 mpy even when the injection rate is double that required to react with all the hydrogen sulphide.
  • Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
  • Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm3 of 4% NaCl, 0.1% NaHCO3) and stabilised crude oil (10cm3 of forties crude), by injection of an aqueous Na2S solution (2.6cm3 of 0.029M) and sulphuric acid (5.6cm3 of 0.05m).
  • the resultant pH was 6.2 to 6.4.
  • the H2S scavenger was introduced into the flask and after a predetermined time interval the residual H2S was determined by injection of 100cm3 of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.
  • Chlorite has been tested with and without lauryl betaine to investigate the influence if any of the corrosion inhibitor on the hydrogen sulphide scavenging ability of the product.
  • Hydrogen sulphide was generated in situ in a sealed vessel containing brine (92cm3 of 4% NaCl, 0.1% NaHCO3) and stabilised crude oil (10cm3 of forties crude), by injection of an aqueous Na2S solution (2.6cm3 of 0.029M) and sulphuric acid (5.6cm3 of 0.05m).
  • the resultant pH was 6.2 to 6.4.
  • the H2S scavenger was introduced into the flask and after a predetermined time interval the residual H2S was determined by injection of 100cm3 of air through the solution and vented via a Drager tube. Experiments were all conducted at ambient temperatures.

Landscapes

  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Preventing Corrosion Or Incrustation Of Metals (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Claims (10)

  1. Une composition utilisable comme agent de nettoyage des sulfures, ladite composition comprenant une solution aqueuse d'un chlorite et un inhibiteur de corrosion, caractérisée en ce que l'inhibiteur de corrosion est un composé amphotère de formule :
    Figure imgb0008
     dans laquelle chacun des R₁, R₂ et R₃ est un groupe identique ou différent choisi parmi les suivants : H, C₁-C₂₄ alkyle, aryle, halogène, hydroxy, alcoxy, groupe carbonylique et hétérocyclique formé par une combinaison d'au moins deux des R₁, R₂ et R₃ et de l'atome d'azote, ledit groupe hétérocyclique éventuellement contenant des hétéroatomes supplémentaires, R₄ est un groupe acide carboxylique ou sulfonique, et n a la valeur de 1-9.
  2. Une composition selon la revendication 1, selon laquelle le chlorite est un chlorite de métal alcalin.
  3. Une composition selon la revendication 1 ou 2, selon laquelle le chlorite est présent en une quantité d'au moins 0,5 mol/mol de contaminant sulfure à éliminer.
  4. Une composition selon l'une quelconque des revendications précédentes selon laquelle les groupes substituants dans le composé amphotère de formule (I) sont résistants à l'oxydation par le composant chlorite dans la composition.
  5. Une composition selon l'une quelconque des revendications précédentes selon laquelle dans le composé amphotère de formule (I), R₁ et R₃ sont des groupes C₁-C₄ alkyle, R₂ est un groupe C₁₀-C₁₅ alkyle et R₄ est un groupe -COO- et n a la valeur de 1-4.
  6. Une composition selon l'une quelconque des revendications précédentes, dans laquelle R₁, R₂ et R₃ dans le composé amphotère sont tels que ensemble ils représentent soit un noyau imidazoline soit une alkylbétaïne.
  7. Une composition selon la revendication 6, selon laquelle le composé amphotère est la laurylbétaïne.
  8. Une composition selon l'une quelconque des revendications précédentes selon laquelle les proportions relatives du chlorite et du composé amphotère sont de 1:0,1 à 1:0,9 en poids/poids respectivement.
  9. Un procédé pour éliminer le contaminant sulfure dans une charge d'alimentation comprenant des courants liquides ou gazeux ou dans des cuves de stockage formant partie d'une installation de traitement de produits chimiques, ledit procédé comprenant la mise en contact de la charge d'alimentation avec une composition selon la revendication 1 à une température comprise dans l'intervalle allant de la température ambiante à 150°C.
  10. Un procédé selon la revendication 9, selon laquelle la charge d'alimentation contaminée est un pétrole brut humide contenant 5-95 % en poids/poids d'eau et 1-1 000 ppm de sulfure d'hydrogène, ladite charge d'alimentation étant mise en contact à un pH de 4,0-6,9 et à une température de 15-60°C avec une composition selon la revendication 1.
EP90302513A 1989-03-21 1990-03-08 Elimination de sulfures Expired - Lifetime EP0389150B1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
GB8906406 1989-03-21
GB898906406A GB8906406D0 (en) 1989-03-21 1989-03-21 Removal of sulphides

Publications (2)

Publication Number Publication Date
EP0389150A1 EP0389150A1 (fr) 1990-09-26
EP0389150B1 true EP0389150B1 (fr) 1993-05-12

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US (1) US5082576A (fr)
EP (1) EP0389150B1 (fr)
DE (1) DE69001575T2 (fr)
DK (1) DK0389150T3 (fr)
GB (1) GB8906406D0 (fr)
GR (1) GR3008652T3 (fr)
NO (1) NO901272L (fr)

Families Citing this family (9)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5225103A (en) * 1989-08-23 1993-07-06 Hoechst Aktiengesellschaft Aqueous aldehyde solutions for trapping hydrogen sulfide in natural gas and crude oil producing plants
DE3927763A1 (de) * 1989-08-23 1991-02-28 Hoechst Ag Waessrige aldehydloesugen zum abfangen von schwefelwasserstoff
US5167797A (en) * 1990-12-07 1992-12-01 Exxon Chemical Company Inc. Removal of sulfur contaminants from hydrocarbons using n-halogeno compounds
US5397708A (en) * 1993-05-13 1995-03-14 Nalco Chemical Company Method for detection of sulfides
US5635458A (en) * 1995-03-01 1997-06-03 M-I Drilling Fluids, L.L.C. Water-based drilling fluids for reduction of water adsorption and hydration of argillaceous rocks
US6258859B1 (en) * 1997-06-10 2001-07-10 Rhodia, Inc. Viscoelastic surfactant fluids and related methods of use
US20070119747A1 (en) * 2005-11-30 2007-05-31 Baker Hughes Incorporated Corrosion inhibitor
US8895482B2 (en) 2011-08-05 2014-11-25 Smart Chemical Services, Lp Constraining pyrite activity in shale
CA2981139A1 (fr) 2015-04-01 2016-10-06 International Dioxide, Inc Composition stabilisee pour lutte contre les odeurs et deshydratation renforcee combinees

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US1908273A (en) * 1930-04-17 1933-05-09 Mathieson Alkali Works Inc Sweetening petroleum distillates
BE528414A (fr) * 1953-04-29
CA1207269A (fr) * 1982-07-26 1986-07-08 Atlantic Richfield Company Traitement des liquides extraits avec le petrole, a l'aide du dioxyde de chlore
US4473115A (en) * 1982-09-30 1984-09-25 Bio-Cide Chemical Company, Inc. Method for reducing hydrogen sulfide concentrations in well fluids
GB2170220B (en) * 1985-01-25 1987-11-18 Nl Petroleum Services Treatment of hydrocarbon fluids subject to contamination by sulfide compounds
US4594147A (en) * 1985-12-16 1986-06-10 Nalco Chemical Company Choline as a fuel sweetener and sulfur antagonist

Also Published As

Publication number Publication date
DE69001575D1 (de) 1993-06-17
DE69001575T2 (de) 1993-08-26
EP0389150A1 (fr) 1990-09-26
NO901272D0 (no) 1990-03-20
GB8906406D0 (en) 1989-05-04
US5082576A (en) 1992-01-21
GR3008652T3 (fr) 1993-11-30
NO901272L (no) 1990-09-24
DK0389150T3 (da) 1993-06-07

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